1. Field of the Disclosure
This disclosure relates to a method of geophysical prospecting which improves the accuracy of seismic migration. Specifically, the disclosure uses well seismic measurements (Vertical Seismic Profiling: VSP) to accurately image reflectors present in the recorded data.
2. Description of the Related Art
In surface seismic exploration, energy imparted into the earth by a seismic source reflects from subsurface geophysical features and is recorded by a multiplicity of receivers. This process is repeated numerous times, using source and receiver configurations which may either form a line (2-D acquisition) or cover an area (3-D acquisition). The data which results are processed to produce an image of the reflector using a procedure known as migration.
Conventional reflection seismology utilizes surface sources and receivers to detect reflections from subsurface impedance contrasts. The obtained image often suffers in spatial accuracy, resolution and coherence due to the long and complicated travel paths between source, reflector, and receiver. In particular, due to the two-way passage of seismic signals through a highly absorptive near surface weathered layer with a low, laterally varying velocity, subsurface images may be of poor quality. To overcome this difficulty, a technique commonly known as Vertical Seismic Profiling (VSP) was developed to image the subsurface in the vicinity of a borehole. In a VSP, a surface seismic source is used and signals were received at a downhole receiver or an array of downhole receivers. This is repeated for different depths of the receiver (or receiver array). In offset VSP, a plurality of spaced apart sources are sequentially activated, or a single source may be activated at a plurality of spaced apart locations, enabling imaging of a larger range of distances than is possible with a single source.
The VSP data acquisition may be performed by conveying the receivers downhole on a wireline after drilling of the well has been partially or fully completed. An advantage of the VSP method is that the data quality can be much better than in surface data acquisition. The VSP acquisition may also be done by conveying the receiver array downhole as part of the bottomhole assembly (BHA). This is referred to as VSP while drilling.
U.S. Pat. No. 4,627,036 to Wyatt et al., gives an early example of the VSP method. Referring now to FIG. 1, there is illustrated a typical VSP configuration for land seismic acquisition. In the exemplary figures, a Vibroseis® source 11 is illustrated as imparting energy into the earth. It is noted that any other suitable seismic source such as explosives could be utilized if desired. In a marine environment, the source could be an airgun or a marine vibrator.
A receiver 12 is shown located at a desired depth in the borehole 14. For the location of the receiver 12, energy would be reflected from the subsurface strata 15 at point 16. The output produced from receiver 12 is recorded by the recording truck 17. In VSP, the receiver 12 would typically be moved to a new location for each shot with the distance between geophone locations being some constant distance such as 50 feet. More commonly, an array of receivers spaced apart by some desired distance could be utilized and/or a plurality of sources spaced apart could be used. Usually, there is an array of receivers: use of a single receiver is rare.
Data obtained by VSP has the appearance of that illustrated in FIG. 2. Wyatt discusses the use of a processing technique called the VSP-CDP method by which VSP data such as those shown in FIG. 2 may be stacked to produce an image of the subsurface of the earth away from the well.
One of the problems with VSP data is the strong downgoing signals that mask the reflection signals that are indicative of the structure of the earth below the receiver array. Accordingly, a method called VSP wavefield separation is used in the processing of 3-D VSP data. The result is the individual extraction of the different kinds of regular waves present in the data: upgoing and downgoing P and S waves and tube waves.
A 3-C VSP wave-by wave separation approach was proposed by Blias (2005, 2007). This method models and subtracts each regular wave. After some modification, it also can be used to separate different waves (primaries and multiples) from surface seismic data. To use this approach, one needs to manually pick time events for each regular wave. For 1D and 2D VSP data, the amount of manual picking is relatively small. For 3-D VSP, the large number of shots dictates that the apparent velocity of each regular wave is dependent upon the source to receiver direction and the offset distance. Picking each wave is therefore a major time-consuming task. The present disclosure addresses the problem of automatic picking of VSP data. Automatic picking also leads to the strongest wave, which may have different type from one gather to another. Sometime, we cannot see all waves on the input VSP gather. This makes manual picking impossible for all waves, and requires additional manual picking after extraction strong events. However, after subtraction strong events, weak events could be recognized by automatic picking (3-C velocity analysis). This provides essential decreasing of manual work in 3-D VSP wavefield separation.